Diamondback Energy, Inc.

Good day, and thank you for standing by. Welcome to the Diamondback Energy second quarter 2024 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Adam Lawless, VP of Investor Relations. Please go ahead.

Thank you, Stephen. Good morning, and welcome to Diamondback's second quarter 2024 conference call. During our call today, we will reference an updated investor presentation and letter to stockholders, which can be found on Diamondback's website. Representing Diamondback today are Travis Dice, Chairman and CEO, Case Van Toft, President and CFO, and Danny Wesson, COO. During this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance, and businesses. We caution you that actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we will make reference to certain non-GAAP measures. The reconciliations with the appropriate GAAP measures can be found in our earnings released issued yesterday afternoon. Well, now I'll turn the call over to Travis Dice.

Thank you, Adam, and I appreciate everyone joining this morning. I hope you continue to find the stockholders' letter that we issued last night an efficient way to communicate. We spent a lot of time putting that letter together, and there's a lot of material contained in the text. Operator, would you please open the line for questions?

Yeah, thank you. At this time, we will conduct a question and answer session. Once again, as a reminder, to ask a question, please press star 101. To withdraw your question, please press star one again. Please stand by. We'll compile the Q&A roster. The first question comes from the line of Neil Dingman of Truist. Your line is now open.

Morning, Travis. Nice results. Travis, my first question is on Truist. sort of the leading capital efficiencies you all continue to highlight. Specifically, you talked about the latest announcement. I think you guys talked about dropping to 10 from 12 rigs and think what that's even versus 14 a few months ago. And I'm just wondering, are the drilling efficiencies so good that you're able to maintain the pace with nearly 30% rigs than just a few months ago? And just wondering how you anticipate or if you anticipate the same type of efficiencies once you take over the Endeavor assets.

Sure. Good question, Neil. The first half of the year was really typified by us doing more with less, and you gave some numbers there, but just to repeat some of those. In January of this year, we estimated that we could get 24 wells per rig per year, and now we're up to 26 wells per year for the rest of the year. You see a similar efficiency gain on the completions where we previously signaled 80 completions per year per crew and now we're up to over 100 completions per crew per year. Those are simulfrac crews. And look, as we look into the future, one of the things that I get excited about is that these efficiencies are things that we don't give back. And so as we incorporate after close the new the new assets from Endeavor, I fully anticipate our operations organization combined with Endeavor's operations organization will be able to continue these results. What's significant about that is when we talked to the market on February 12th announcing this deal, one of the biggest, the biggest synergy that we talked about was being able to apply Dymovac's current DNC cost on a larger asset. And I'm pleased to say today we're significantly below where we were in February. So that just accrues the benefit to our shareholders and really supercharges the delivery of the synergies that we were talking about. So, yes, Neil, I'm very confident that we'll be able to continue this leading-edge capital efficiency on a larger asset base.

Great to hear that. I want to ask just quickly on shareholder return plans, maybe just on sort of broad strokes specifically, how would your plan vary? I mean, obviously, oil prices are jumping around, could be anywhere from, you know, $90 to $70 environment. I'm just wondering, given your market, you know, sort of the leading costs that we see on slide nine, you know, I'm just wondering, depending on where oil prices go, is that just a matter of having more free cash for buybacks and variable dividends, or would there be any other changes we see in a high oil price environment versus a low oil price environment?

Yeah, Neil, I mean, you know, I think the key point here is, you know, we've always had a very flexible return of capital program, you know, since the very beginning when we put this in place in 2021, we've said we'd like to be able to flex between buying back shares and paying a variable dividend. And, you know, we take, you know, we take that capital allocation decision very, very seriously. We're set up in a way where if you have periods of weakness, like we've seen over the last week or two, that's when the buyback kicks in. If it continues to be weak, we'll continue to buy back more shares. That's the benefit of having a low break even on your capital program, low break even on your base dividend, and continuing to generate free cash flow down to much lower numbers than peers or than what the market's used to. I think we're excited. If things do stay weak, we'll flex that buyback and be aggressive there. And if things improve and we have a good quarter in the 80s or 90s on crude, then we'll pay a big variable dividend. But I think that flexibility has been very, very advantageous to our shareholders over the last three years.

How long has that break even gotten down to?

You know, listen, we were very focused on looking at our base dividend break even at $40 crude. So, you know, mid-cycle capital costs, $40 crude, we could keep production flat. You know, I don't think in a $40 crude scenario we would do that. I think kind of lessons learned from what we've seen through the cycles over the years is that it's okay to let production decline if we were in a very, very weak commodity price scenario. In that scenario, we should be allocating 100% of our free cash flow or even more to buying back shares because in that situation, your share price is going to likely be very weak. So we're really trying to move the capital allocation decision from the field and the assets to what do you do with your free cash flow, and that I think is a good place to be.

Thank you so much.

Thank you. Our next question comes from the line of Neil Mataw of Goldman Sachs. Their line is now open.

Yeah, good morning and congrats again on very strong execution here. You know, you've talked about getting that net debt level lower post-transaction. In that case, and Travis, how do you see yourself doing it? Is it through asset sales or through organic free cash flow generation? Just your perspective on the asset sale market, recognizing you did some small deals here in the quarter.

Yeah, Neil, I mean, I think when we announced the deal, you know, we were very conscious of the cash stock mix that we put in place for the Endeavor merger. You know, I don't think we put – we didn't put so much cash in the deal that we had to be a seller of assets. But what you've seen us do is, you know, sell – multiple things now over the last, you know, couple quarters that start that up, right? We sold a little bit of our Viper ownership to take some risk off the table and get some cash in the door. We sold, you know, our interest in WTG, West Texas Gas, to Energy Transfer, and we'll get some cash in the door. And then little things like our little Monop sale that we did last quarter, you know, all that kind of almost adds up to a billion dollars, which on top of free cash flow generation between January 1st and today is going to reduce the cash outflow burden, uh, you know, for the endeavor deal. So I think we've, we planned on looking at the deal, uh, as, as a de-levering process through free cashflow, but the asset sales are a kicker that accelerates that. And I think we're highly focused on getting to 10 billion as quickly as possible. And then I think, you know, things can, can slow down from there, but I don't think you'll see us be a forced seller of assets, uh, post deal close. And, uh, I think we're going to be very, very stingy on keeping operated properties in the Permian because they're kind of worth their weight in gold right now.

Yeah, it makes a ton of sense. And then just your perspective on managing gas price volatility. First of all, what are your latest thoughts on Matterhorn and when that comes in? And then secondly, how do you mitigate some of the risks around gas prices so you can really from the margin that you deserve on the oil side of the equation?

Yeah, that's been a big topic lately. Obviously, we need to start making more money on our gas and the Permian and Diamondback specifically. If you look back to the history of Diamondback, we've grown through acquisition. A lot of the deals that we've done have come with marketing contracts where we don't control the molecule much further than the wellhead. And so what we've been doing over the last, I'll call it five years, is that as contracts roll off, we've been taking advantage of that and taking kind rights on that molecule. We started with our commitment to Whistler and have grown that. That combined with Matterhorn, we'll have a little bit of gas on both of those. And then I think you saw press release last week that we're going to be a participant in the next pipeline from those guys, the Blackcomb Pipeline. I just think that fits the strategy of let's take control of our molecules and see what we can do with them. I don't think that stops at pipeline commitments. We're really looking at power needs in the basin, things like our Verde gas to gasoline plant, and trying to find ways to create a local market here in the Permian because it's a shame that we continue to sell gas near zero or below zero. So it's on us to continue to improve that portfolio, and I think with size and scale and time, we'll be able to do that.

Thanks, Casey.

Thanks, Neil.

Thank you. Our next question comes from the line of Arun Jayaram of JPMorgan Securities. Your line is now open.

Yeah, my first question is just on the efficiency gains you highlighted in the letter. It looks like you're pushing your drilling cycle times to 26 wells per rig and on the completion side pushing 100 wells per frac fleet, simulfrac fleet. I was wondering, Case and Travis, if you could describe what the drivers of those efficiency gains are and perhaps help us think about what's underwritten in the pro forma, you know, $4.1 to $4.4 billion guide for Endeavor for Calendar 25?

Sure. On the rig side, you know, we specifically talked about bit and bottom hole assembly improvements. And, again, that's not necessarily the adoption of some new emerging technology. I think it's really another example of what our guys do really, really good, which is a laser-like focus on every decision that's made. They measure almost every attribute of drilling the well and they seek for improvement and they compete against one well versus the other and we pay bonuses to the crews out there when they execute in a stellar fashion. So it's not something again that's easily repeatable and it's not a shelf item that someone can go take but it's a culture of execution that's always been part of this business. On the completion side, There's been some design changes where we've increased rate, but we've also continued to try to optimize the exact way that we mobilize equipment. We've done some changes on some pipe down hole that allows a greater rate with less friction loss. Again, it's nothing that's a marquee item, but it's just intense focus on doing what it is that we do, which is really, really execute well when we convert ROC into cash flow.

All these things certainly have accrued to us since we announced the Endeavor merger in February. I think, as Travis mentioned earlier in the call, these are permanent items that aren't going to go away from service cost inflation or deflation. As we work through the pro forma model, we're probably thinking that we're going to run closer to 18 to 20 rigs next year versus 22 to 24 you know, a while back, and, you know, closer to four to five Somoprag crews versus five plus. So, you know, we're certainly modeling these things, accruing for the good guys, and, you know, it'll only give us a head start on the promises we made on 2025 numbers.

Great. My follow-up is just on the raised production guide. You raised your oil guide at the high end by, you know, close to 1.5% just under that, and then you took up CapEx. Case, one thing that wasn't quite intuitive is that you're completing 7% more feet on a net basis. And so one of the questions that's come in is would have thought maybe the oil increase would have been a little bit higher based on that level of completed footage. But maybe you could help reconcile that for us this morning.

Yeah, I mean, you know, I think – you know, I don't think wells are completed like they – look to be completed in the spreadsheet, right? I mean, in 2022 well paths, you know, you move one path from 2023 into 2024, and you got 22 extra wells. So, you know, we kind of moved almost, I think, 30 wells from 2023 into 2024, so our well count's a little bit higher than maybe, you know, a true level-loaded run rate would be. But, you know, I think we're also just preparing a room for a major acquisition to close, and And I think we're doing everything we can on our side to be prepared to hit the ground running and hit numbers right away and do exactly what you would expect us to do. So I think more importantly, it's the more drilled lateral footage, you know, for less CapEx that gives us a lot of flexibility in the second half of the year and carry that momentum into 2025.

Makes total sense. Thanks, Travis.

You bet. Thanks, Aaron. Thanks, Aaron.

Thank you. Our next question comes from the line of David Deckelbaum of TD Cowan. Your line is now open.

Hey, Travis, Kays, Danny, and team. Thanks for taking my questions. You know, I wanted to follow up on some of the earlier questions. You've obviously seen a lot of field efficiencies, particularly on the drilling side. You've lowered the mid-lid and footage costs down, you know, I guess around $20-some at the midpoint, but Curious, as you approach this 3Q, potentially 3Q or 4Q endeavor closing, are there any parts of the efficiencies that you're seeing that you don't think that you could accomplish as a synergy here? Because it would seem like that $300 million or so of synergies that you apportioned to just CapEx savings is increasing by the day.

Well, that's why I highlighted, David, that where we are today is much better in performance and execution than where we were in February when we talked to you about this deal. These are cultural elements, this attention to detail, this focus, this laser-like attention to execution, and we look forward to bringing on our new friends from Endeavor. From what we hear from them anecdotally, they're seeing similar efficiency gains as well, too. When we put the two cultures together, I expect it to be an adder, not a detractor, when we actually put the two companies together here before too much longer.

I appreciate that. Just a follow-up to that, you've also seen the benefits of longer lateral progression I guess relative to your original plan this year, I know one of the things you highlighted with the endeavor deal was the potential increase of lateral lengths to 15,000 footers and beyond on a given 100,000 plus number of acres. How do you see the progression, I guess, into next year and then 26 in terms of lateral length relative to where we're at today? Or is this something that's a longer term endeavor?

Well, first we're going to have to get the two assets put together, which we obviously can't do that currently. I'll let Case answer the synergy question specifically, but I wanted to highlight something that we talked about in our earnings release and our stockholder letter was that we drilled a 20,000-foot lateral well in under eight days, under nine days.

Seven to eight days.

Yeah, seven to eight days. And longer is not going to be a problem. You know, it's just we need to make sure we have the least geometry to be able to drill even longer wells.

Yeah, I mean, I think, David, on the plan, you know, we can't put anything together until post-close. But, you know, I think the priority for the teams right now is, you know, what does the plan look like end of 24 and into 25 post-close? And then what do the projects look like, you know, starting to back out to 25 and into 26 that – start to extend laterals. I mean, I think, you know, I think holding the level that we have this year, you know, almost 12,000 feet on average for 300 wells is a pretty stellar number that we should probably, you know, look to maintain. I think going much further than that for a full program of, you know, 500 plus wells a year is going to be tough to do. But, you know, I don't think the guys are scared of drilling to 20,000 feet. And if we have those opportunities, we'll take advantage of them.

Appreciate the cover, guys.

Thanks, Dave.

Thank you. Our next question comes from the line of John Freeman, Freeman James. Your line is now open.

Good morning, guys. First topic I just want to follow up on is on the return of capital framework. And when you look at slide six and just sort of think about, again, the efficiency gains that have are really impressive and as over time as that sort of drives that maintenance CapEx or reinvestment rate lower, should we think of maybe the first kind of evolution of that return of capital framework just being that creates like a bigger, I guess for lack of a better word, wedge that can go to that base dividend? Is that more likely kind of the way it would evolve as opposed to maybe increasing that 50% plus that's going to shareholders overall.

Yeah, John, I think those are two separate decisions, but I think you hit the nail on the head on as efficiencies accrue and our decline rate shallows over time and your balance sheet shrinks over time, that should create room there between your break-even and your $40 dividend break even. So I think that's how we're still going to look at it. I think we see $40 on the EMP side as a very well protected number. Um, you know, we're still going to buy puts at, you know, right now we're buying them at 55, $60 crude, but eventually probably reduce the value of our put buying down to closer to 50 just to protect, you know, the extreme downside scenario. And, you know, and I think the rest of the free cash, you know, we did move back from 75% of free cash go into equity down to 50 and But that doesn't mean, you know, that number is not going to be higher in the future in times of stress. I think in times of stress or significant stress, the number should be a lot higher than 50% of free cash going to equity. And when things are going well, you know, the number should be closer to 50 and we'll continue to build a fortress balance sheet. You know, I've been very, you know, pleased with the response from our large shareholders on cutting back to 50% of free cash going to equity because they want us to have a more fortress balance sheet than we even thought going into the deal. I think that's been a pleasant relief and it allows us to build a lot more cash and be ready for the inevitable down cycle in this sector.

John, I think a good way to demonstrate or a good way to visualize the board's commitment to this Sustainable and growing dividend is on slide seven. Go all the way back to 2018 when we initiated the dividend. And you can see on that slide the growth rate. And on the bottom half of that slide, you can see that our commitment has translated into almost $8 billion of capital returned to our shareholders. So it's a meaningful lever that we have as a company and the board's commitment to continue that sustainable and growing dividend.

That's great. And then just my follow-up, when we take these efficiency gains that have allowed you all to basically pump the brakes on rigs and frac crews in the second half of the year without missing a beat on the original production plan, is there any environment where you all would choose to basically just sort of plow ahead at the run rate you all were on in the first half of the year and just sort of allow production growth? to accelerate? Is there any sort of an environment where you would foresee that ever kind of occurring?

Yeah, just where we sit right now, John, that's not a logical scenario that we see playing out in the next, you know, six months, three, four quarters.

Yeah, I mean, historically, we've tried to, you know, post-COVID favor free cash flow generation over growth. And I think you're seeing that trend continue here with what we're doing in 2024.

Thanks, guys.

Thank you. Our next question comes from the line of Scott Henold of RBC Capital Markets. Your line is now open.

Yeah, thank you. You know, there's been a lot of talk of good operational efficiencies. Could you maybe pivot and talk about what you're seeing in terms of well performance of productivity you know, over the last year? Is it pretty much status quo on an apples-to-apples basis, or are you seeing some gains there as well?

You know, I would say generally on a yearly average basis, we see this year as kind of going to be flat to last year. But I think what's unique is that, you know, we're adding a lot of Wolf Camp D, a lot of Upper Sprayberry, more Joe Mill. You know, we're adding more zones to our midland development plan and getting the same output in terms of productivity. And so, you know, the resource expansion story probably goes sometimes unnoticed in the Permian, but, you know, talking about a zone like the Upper Sprayberry where we haven't, you know, hadn't drilled a well until two years ago outside of one energy well in 2018, now becoming part of the, you know, stack of co-development without a degradation in well performance is, is truly what makes the Midland Basin unique. So I think we've had a few really, really good years of well performance. We're always trying to keep pushing the performance side. But I think this year has been a year of cost gains versus well performance gains. But that doesn't mean there's not significant inventory expansion going on across our portfolio.

Thanks for that. And then my follow-up question is, you kind of highlighted, obviously, all the drilling efficiencies again. And I think you made a comment that, you know, from what you understand, the Endeavor folks are seeing some similar stuff. But can you give us some context, like, you know, based on what you can see from your understanding at this point, you know, where is Endeavor relative to where Diamondback is? So just trying to get a sense of You know, should we expect, you know, once the merged company comes together, you know, there's still some work to do to get it back, to get it all toward where Dimeback is right now, or is it going to be pretty much just, you know, hitting the ground running?

Well, it's going to be hard work for sure. It's our job to do that hard work and make it look easy for you guys. You know, there's some decisions that we'll make pretty soon, you know, after we combine the two companies together. you know, one would be the use of clear drilling fluids, and the second would be to put more of the frac operations onto simulfrac. So, those are the two biggest levers that have the quickest change. But look, we're also going to, like we've always done, check our egos at the door and make sure we seek to understand, you know, what the Endeavor team's already doing. And historically, that's generated better results, you know, when we We seek first to understand and then pick the best path forward with the combined inputs from Legacy Diamondback and the new asset, new management from Endeavor. So we're going to make it look easy, but it's hard work behind the scenes. But I'm really confident that both of the two leadership teams are going to be able to pull this off and make it look good.

Yeah, I mean, I think from a numbers perspective, the way we're thinking about it is the pro forma business will be running basically kind of 21, 22 rigs off the start. And then, you know, by 2025, we'll probably be averaging closer to 18 to 19 combined.

That's good color. Thank you.

Thank you. Our next question comes from the line of Bob Brackett of Bernstein Research. Your line is now open.

Good morning. Following up on those intriguing operational efficiencies, you mentioned the average of 26 wells per rig year, 100 wells per crew. What's the pace setting rig or crew look like? Is it significantly ahead of that, or is there a big opportunity to grab?

Hey, Bob. It's Danny. Yeah, I mean, I think the crews and the rigs, they're pretty well all within a margin of error of each other in their performance. We've been really pretty active on fleet management over the past few years and continue to optimize our fleet where we see dwindling performance. The best thing about our operation is the collaboration we have between the teams on sharing best practices on best-in-class rigs. When we look at the rigs across the board, there's always one pace-setting rig, but That tends to move around as we share best practices and the other rigs catch up and then another one will pass that rig. Not one unique standout that's driving that number. It's pretty well across the board at that same level of efficiency.

We do have a pretty healthy competition between internally and then we also, every quarter we look externally and there's a pretty healthy competition. You know, that's why in our stockholders' letter, you know, I talked about in this quarter in the Midland Basin, the drilling team got over 20,000 feet with a single bit run, and that represents a record in the Midland Basin. So I'm sure that record will fall, but it's just part of the culture of evaluate, you know, internally and externally, and compete to win, and that's what our organization does.

Yeah, very clear. Quick follow-up along that line. How do we think about the relative prize between pulling on that ROP lever versus reducing non-productive time or even reducing MOB, demob time? Are they equal size prizes or is one the more obvious of the three?

You know, I think it kind of moves, but, you know, you're getting to the point in time where, you know, there's the little things we're focusing on now are the efficiency drivers. You know, we talked in the last call about the guys, you know, focusing on pipe makeup speeds because that was, you know, where they saw the most NPT time on a well was just how long it takes them to break and make up pipe. And, you know, we're constantly looking at where that dead space is in these jobs and trying to attack it. And we don't just attack one dead space. We attack them all at the same time. And And I think, you know, NPT time has been a focus of, you know, coming out of the really aggressive, you know, activity levels we saw in 23. And, you know, we've really, you know, done a good job of reducing NPT time, but there's certainly always things we can focus on there to continue to drive, you know, uptime and drive, you know, constant performance and not waiting on the sidelines for something to be fixed.

When we look at those details, we do it every quarter for sure. What Danny is talking about requires a great deal of collaboration across all the teams. Even though I emphasize the competition aspect of what it is that we do, the collaborative aspect is really where this sits home because when one team finds a solution, it's quickly shared with all the other teams internally. And in a similar fashion, if we find something externally, we quickly adopt that as well too.

Very clear. Thanks.

Thank you. Our next question comes from the line of Roger Reed, Wells Fargo Securities. Your line is now open.

Yeah, thank you. Good morning. Hey Roger.

Hey Roger.

Congrats on another solid quarter guys. Just a couple of questions kind of operating focused here. One, if we look at the production beat here in the second quarter, you got it on NGL and gas. We were just sort of curious, we kind of figured maybe you strip more liquids out of the gas, but then you would have lower gas production. maybe a little bit of insights into what's lifting the NGL side and keeping the gas production up?

Yeah, I think on the NGL side, we're trying to put as much ethane as you can into the NGLs to get them out of the basin. We even probably, throughout the second quarter, we saw obviously a lot of gas price weakness. So we did take a couple of our highest GOR wells down for a month or two to ease that pressure. So I think even in the face of that, you know, the gas curve continues to outperform expectations. But, you know, we kind of even curtailed a little bit of oil to make sure our gas production was a little bit lower in the quarter, which we kind of continued in the third. So, you know, we just have a lot of gas production out of this basin, and that's kind of why, you know, we have such a focus now on on trying to generate more value for the gas that we're producing, whether that be in basin or out of basin.

Just to add to that, the focus around environmental performance has driven a lot of decisions to not burn gas in the field for energy consumption and instead convert that energy demand to electrical demand, and so you're seeing a lot of gas that would have otherwise been burned in the field to run our operation being put down the pipeline. On top of that, the focus on reducing flaring, those are all things that send gas to sales and get reported as a production number that's driving some of that increase you're seeing across the basin.

Okay, that's helpful. Thanks. And then just coming back to the drilling efficiencies and the completion efficiencies going from 24 to 26 wells, 100 completions, can you give us an idea of maybe where the, you know, kind of upper 10% or upper quartile is? In other words, I'm trying to think of if 24 went to 26, is the best 30, you know, and that's where you can ultimately go, or it's a much tighter dispersion, you know, so it's 26 the average, best 28, maybe worse is 24. I'm just trying to get a feel for the further improvements, kind of the same idea on the completion side.

I think, you know, that's a good question. It just depends, but we certainly have some rigs that are drilling at a pace of 30 plus wells a year. It just depends on which zones and lateral lengths and all that kind of stuff, but You know, we're really focused on, you know, pad cycle times and how to reduce the full pad cycle time. These are large pads. And, you know, give driving flexibility in the plan by reducing that cycle time on the pads is really what's important to us. And so, you know, if we have one rig that's outperforming the others in one zone, we want to look at that zone and what that rig's doing and kind of share it with the other rigs so that we can We can accrue that benefit to all the pad development across our portfolio.

Gotcha. And maybe if I could just clarify on that, three-mile laterals versus something less than that as a percentage of total?

I'm sorry, just to rephrase your question, you're asking what's their percentage of three-mile laterals to... Yeah, you said it depends on what you're drilling and which zones.

I was just curious, is there... Obviously, it would take not as long to drill a lesser-length lateral, but I was just... Is there a percentage that you offer of the much longer lateral wells?

I think our 15,000-footers this year were like at 25-ish percent of our development per

Yeah, you know, listen, the rig per year number is an output of getting 300 wells per year drilled, right? So it's really about net lateral footage or gross lateral footage drilled per year per rig. You know, I think, you know, Danny's talking about 30 wells per rig. Well, you know, I think if we're drilling more Wolf Camp D with a particular rig, that rig's going to be a little slower. But, you know, I think the general, you know, standard Wolfberry development is, you know, pushing that upper echelon, but we really see the rig count as the output of what we need to do from a drilling perspective on hitting production guidance.

All right. Thanks for indulging me the extra question, guys.

No, no problem. Thanks, Rodney.

Thank you. Our next question comes from the line of Jeff Jay of Daniel Energy Partners. Your line is now open.

Hey, guys, just one quick one for me. I'm just kind of curious how you think about the potential for Trimofrac in your portfolio, kind of especially after Endeavor closes.

Yeah, I mean, we look a lot at Trimofrac and, you know, the struggle for us is the infrastructure spend we'd have to implement to get to Trimofrac across our portfolio. And does that additional infrastructure spend, do we recognize the return on that from the efficiency gains from moving from Simofrac to Trimofrac? We think the cost benefits somewhere to $10 to $15 a foot to move from simulfrac to trimulfrac, certainly something we would pursue in areas where we have the infrastructure in place to do so. And if we have available enough development in those areas to dedicate a trimulfrac crew, you would see us move that direction very quickly.

Excellent. Thank you.

Thank you. Our next question comes from the line of Charles Mead of Johnson Rice. Your line is now open.

Good morning, Travis Case and the rest of the Diamondback team there. Hey, Charles. Travis, thank you. I think you really tantalized a lot of people with that metric. I really appreciated it, you know, with that metric. 24 wells a year, 26 wells a year, but I thought Case's comment was really interesting in that I've been focused on that. I think other callers have been, but really that's the output rather than the, you know, it's kind of a manifestation or an indicator rather than a driver, if I understand Case correctly. And so if that's the right way of looking at it, when I look at the other pieces of your guidance, you've actually increased the lateral length a little bit, and you've increased the well count a little bit. And so is the delta on the drilling site actually a little bit bigger, the delta, the improvement you've seen since your initial plan than that 26 over 24 would indicate?

Yeah, I mean, I think so, Charles. I think the point I was trying to make is that As a public company that has public guidance and quarterly guidance, we really work from guidance backwards and we make what looks like an easy output on the surface is very difficult below the surface. There's a lot going on in terms of the teams being able to move things around and add rigs here and drop rigs there. The plan isn't always the plan. We've got to be nimble and work together as a group. I think that that harmony we have across all of our functions is what makes us pretty unique, particularly, you know, also given that we're in one basin. So I would say the drilling improvements this year have been more surprising than the completion improvements because we always kind of thought that drilling was already near the asymptotic curve of what they've been able to do. So, you know, not to knock the frack guys, but the drilling improvements probably supersede the frack improvements here today.

Thank you for those comments, Casey.

That's all from me. That's a little test for the frat guys to step it up next quarter.

I'm glad to put the ball in the tee for you there. Have a great day. Thanks, Charles. Thanks, Charles.

Thank you. Our next question comes from the line of Paul Chang of Scotiabank. Your line is now open.

Thank you. Good morning, guys. Good morning, Paul. Trevor and Casey said... we appreciate that about the great improvement in your result, but just curious that, I mean, over the next two or three years, if we're looking at the productivity improvement in drilling and completion, is that one or two areas you see as the biggest potential for you? And will you be able to also quantify on that? And the second question is that, If we look at for a performer over the next couple of years, I mean, in order to maintain a flat production post-Andeva, I mean, how many wells that we need? Is it 500, 520, 550, any kind of rough idea? And also that do you have what Andeva gas pricing right now? Are they all in the Waha Basin or that they also spread? Thank you.

Well, I'll talk specifically about your look ahead for two to three years. And I think if you put it in one bucket, it would be in the downhole sensing technology that allows the bit to stay in the best rock the highest percentage of time. And then on the completion side, understanding using downhole sensing where you can place the most frac energy in the most efficient way that creates the greatest stimulated rock volume. And these sensing technologies are evolving very, very rapidly. I think before too long, we'll be able to actually sense in front of the drill bit and drill towards the target rather than drilling past it and making adjustments. And that sounds like a small change, but I think the sensing technology that we're right on the cusp of having some of those problems solved is going to be a real game changer for our industry.

Paul, on your well count question, I think kind of low 500s is a good place to start as low 500 dwells per year. But as the land efficiencies accrue to us and laterals extend and the decline rate shallows a bit, you probably start to get below that 500 number should production stay flat. Now, if know things are if things are a market that's conducive to growth that that probably changes but on a flat basis it's you know more capital efficiency less capex less wells to hit the same numbers longer term great and casey do you have an idea that what and deeper gas exposure to your waha yeah so listen you know we we've seen what what exposure and endeavor has um you know i do think there's going to be a lot of opportunities for both of us combined to get gas out of the basin. You know, we got to close the deal first and then we can start making decisions, but I think we're both, both companies are aligned that, you know, more gas needs to get out of the basin and less exposure to WAHA.

Okay. Thank you.

Thanks, Paul.

Thank you. Our next question comes from the line of Leo Mariani of Roth. Your line is now open.

I wanted to follow up on some of the comments you made around the share buyback. Obviously, you guys had leaned more on the variable dividend in the past quarter, but you certainly kind of indicated from some of your comments here on the call that given the recent pullback in the stock and the sector, the buyback was looking more palatable. Just trying to get a sense if you guys are able to start executing on the buyback here. post-quarter? Are there some restrictions in place with respect to the Endeavor deal that would prevent some of that over the next couple months until the deal closes?

Yeah, Leo, I don't think there's any more Endeavor-specific restrictions. Obviously, we're now, you know, we're reporting earnings today, so we're in a blackout day. But, you know, I think, you know, these periods of weakness allow us to step in, and we freewire the buyback for every, you know, every blackout period. And, I think if we continue to see weakness here, we'll get opportunities. We just have a little more flexibility if the window is open versus closed.

Okay. Appreciate that. And then just in your comments here and your guidance for the rest of the year, it looks like third quarter CapEx is coming down some versus QQ. It certainly sounds like activity is falling a little bit in the second half of the year and some of the You know, the OFS cost reductions are kind of rolling through as well. I mean, do you see, you know, standalone without Endeavor, you know, CapEx continuing to kind of drop a little bit and activity kind of dropping a little bit, and 4Q as well, just trying to get a sense that that's kind of the low point for spend and activity, you know, on a standalone basis here?

Yeah, you know, I think it'll be the low point for spend because we're a cash CapEx reporter. I think the low point for activity will be this quarter. So I think we'll probably bring back our fourth simulfrac crew, you know, end of this quarter, end of the beginning of next quarter. That's all on a standalone basis and probably bring back a rig or two, but not much more than that. So I would say Q3 is the low for activity. Q4 is the low for, you know, for CapEx.

Okay. Thanks. All right, thank you. Our next question comes from the line of Kalei Akamain of Bank of America. Your line is now open.

Hey, good morning, guys. Thanks for taking my questions. A lot of focus on field efficiency, so I'll leave that alone. I want to ask you guys about Deep Blue. The team over there continues to be very inquisitive. It looks like that business has run about maybe 20% plus or minus over the past year in terms of capacity. Can you talk a little bit about the growth outlook for that business? Potential endeavor, dropdown included, and maybe help us understand what the skill of the business could be once it matures.

Yeah, listen, I, you know, I think we're very pleased with what the deep blue team has done, uh, in a short period of time. It's kind of exactly why we, we did the deal with them, right? They they've gotten a lot of, uh, third party wins, you know, wins that would Diamondback wouldn't get if Diamondback was trying to gather someone else's water. And on top of that, you know, a little bit of M&A to boost capacity and reduce costs there. So, you know, we're really excited with what they're doing. You know, Endeavor has a very impressive water system. You know, that could be a candidate to merge with Deep Blue. But, you know, I think the price has got to be right for Diamondback shareholders, and that's what we're focused on first. But, yeah, listen, they're doing a really good job. building a sizable business on the water side. And, you know, with the amount of water that it takes to run, you know, multiple simulfrac crews at the same time, you know, you're moving hundreds of thousands of barrels of water a day at low cost. So very, very impressed with what they're doing. I don't think they're ready to monetize yet. It's a longer-term investment for us, and we look forward to continuing to support that business.

Okay, from numbers, given the size of Endeavor, does it potentially double the size of that business?

It's probably a little less than double. You know, probably about two-thirds the size of the business today. But it has a lot of capacity and really moves into that eastern Martin County area and connects the system nicely.

Thanks for that. And then maybe following up on your comments on Wolf D and the Upper Sprayberry, Can you talk a little bit about that program for this year? Talk about how you're layering those zones into your development plans, whether they're co-developed with other zones, for example, and if there's any learning to take away from this 24 program.

Yeah, I think, so we added the upper spray berry as a test, well, kind of in the North Martin area, like Case mentioned a couple years ago, really pleased with the performance of that. Well, This year we've tested it in a co-developed fashion, and like Kay said, we're not seeing any real degradation there. What we plan to do going forward is to add that to the development zones for the North Martin area.

Wolf Camp D, I think we have some tests that are co-developed and some tests that are standalone. There are certain areas where the Wolf Camp D is significantly deeper than the Wolf Camp B and we're not seeing communication. And there are some areas where it probably just makes sense to develop it with the stack because of above ground efficiencies. Yeah, I think that's right.

We tested the Wolf Camp D kind of in that same North Martin area and really not seeing any communication with the Wolf Camp B. So we think it's a zone that we can come back and get. or where it competes for capital, we'll add it to the stack.

That's awesome. I appreciate that, guys.

Thank you.

All right. Thank you. I am showing no further questions at this time. I would now like to turn it back to Travis Stice, CEO, for closing remarks.

Thank you again for everyone participating in today's call. If you've got any questions, please reach out to us using the contact information we've previously provided. Thank you and have a great day.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.